This invention relates to a steam foam enhanced oil recovery process. More specifically, this invention relates to an improved method of displacing oil within a subterranean reservoir by injecting into the reservoir steam and an improved steam foam surfactant, which rapidly forms a strong steam foam in the reservoir and may be used in combination with other steam foam surfactants.
Many hydrocarbons or oils are too viscous to be recovered from subterranean reservoirs without assistance. These heavy oils can be recovered through the use of steam drives which heat the formation, lower the viscosity of oil, and enhance the flow of oil toward a production well. However, after initial injection breakthrough at the production well, the injected steam preferentially follows the breakthrough path. Also, except near the injection and production wells, the active steam zone in the reservoir tends to rise to the upper levels of the oil-bearing formation. Thus, the total amount of the formation that is swept by the steam injection is limited.
Surfactants have been injected along with steam to create a surfactant-enhanced steam foam flood. The combination of steam and steam foam surfactant results in a steam foam, which is a dispersion of steam vapor in a continuous water phase, wherein at least part of the steam vapor phase is made discontinuous by liquid films, or lamellae. The presence of this foam is exhibited by a reduction in the rate at which the steam travels through the reservoir. The foam reduces mobility of the steam both in the upper levels of the oil-bearing formation, and toward the production well. This mobility reduction results in more efficient heat transfer to the oil, which increases oil recovery at the production well and results in lower average residual oil saturation in the reservoir when the steam foam drive is completed.
Numerous prior processes have involved various uses of steam in conjunction with a surfactant, and improvements to such processes. U.S. Pat. No. 3,292,702 suggests a steam soak process in which an aqueous surfactant is injected ahead of the steam to provide an increased injectivity during the steaming period and a greater rate of production during backflow. U.S. Pat. No. 3,357,487 reveals injecting a solution of surfactant prior to or during a steam injection so that a band of the surfactant solution is displaced by the steam. U.S. Pat. No. 3,412,793 suggests that, in a relatively highly stratified reservoir, a steam soak or steam drive process for recovering oil is improved by temporarily plugging the more permeable strata with foam. U.S. Pat. No. 4,086,964 discloses recovering oil by injecting a steam foam-forming mixture through a steam channel which extends essentially between injection and production wells. U.S. Pat. Nos. 4,393,937 and 4,488,976 describe a steam foam-forming mixture in which the surfactant is a particularly effective alpha olefin sulfonate as well as methods of using such a mixture in steam drive or steam soak oil recovery processes. U.S. Pat. No. 4,488,598 discloses a steam and gas distillation drive using a foamable surfactant. U.S. Pat. No. 4,597,442 suggests a preflushing solution for increasing the rate at which the injected steam foaming surfactant is propagated through the reservoir by reducing ion-exchange effects. U.S. Pat. Nos. 4,556,1107 and 4,607,700 disclose a steam foam injection process improved by the use of alpha olefin sulfonate dimer surfactants. U.S. Pat. No. 4,609,044 describes an alkali-enhanced steam foam drive or soak process for recovering low gravity acidic oil. U.S. Pat. No. 4,617,995 discloses injection of a pretreating fluid ahead of at least some of the steam and steam foaming surfactant to increase the rate of surfactant transport and decrease the amount of surfactant required. U.S. Pat. No. 4,643,256 suggests a steam foaming surfactant mixture which is effective even in the presence of multivalent cations.
Until a steam foam drive is completed, the major indicators of the effectiveness of the operation, and of whether or not foam has formed in the formation, are the injection pressure and a temperature profile. An increase in steam injection pressure indicates that mobility of the steam within the reservoir has been reduced. A temperature profile that is relatively uniform, over that portion of the formation into which steam is injected, indicates that the steam is being deflected from breakthrough paths and zones of greater permeability, and is advancing through the formation as a uniform front. The steam injection pressure is easy to determine from equipment used on the surface as part of a steam foam drive operation. However, the formation temperature profile, which indicates the relative amounts of steam entering the formation at various depths, requires the use of downhole equipment to measure the temperature of the formation at various depths. Also, such a profile is best determined from an observation well, rather than the well where steam injection occurs. Consequently, although steam injection pressures are monitored on an ongoing basis, temperature profiles are determined only infrequently.
To maximize the rate at which oil is recovered, it is desirable to use a steam foam surfactant which forms foam rapidly in the reservoir. When foam forms rapidly, and after the surfactant has traveled only a short distance through the formation, the beneficial effects of foam will occur closer to the wellbore. These beneficial effects include steam mobility reduction, more efficient heat transfer, and additional oil recovery. The foam will impact a greater portion of the target formation if it is formed closer to the wellbore. This incremental effect may be particularly significant in steam soak operations, which typically impact a smaller target volume within the formation than steam drive (well-to-well) operations.
Once injection of a typical steam foam-forming mixture starts, there is often a lengthy period of time, which may be from a day to several weeks, before foam forms and an increase in steam injection pressure is observed. Foam generation may be delayed by interaction of the surfactant with the residual oil saturation near the wellbore, by adsorption of the initially injected surfactant on reservoir mineral surfaces, or by the nature of the permeability distribution in the near-wellbore region of the formation. Usually, the steam foam surfactant must travel some minimum distance through the reservoir before it forms a foam. When foam formation does not occur within the expected time period, the operator will often take expensive remedial steps, such as increasing the concentration of surfactant injected. Alternatively, particularly when a significant amount of time has elapsed without a pressure increase, the operator may simply eliminate surfactant injection and abandon the recovery project. In such situations, rapid foam formation offers the practical advantage of providing the operator with a positive and rapid indication that the enhanced oil recovery process is operating as desired. This can prevent both a potentially uneconomic use of surfactant injected into the formation, and premature abandonment of a potentially successful recovery project.
As part of this invention, a group of surfactants which generate foam rapidly, and are suitable for use as steam foam surfactants, is identified. The foam strength provided, and oil recovery produced, by the rapidly foaming surfactants appears at least comparable to those of steam foam surfactants currently in use. However, these surfactants currently cost more than some other steam foam surfactants, and may, for that reason, be considered less desirable for use in a steam foam recovery process. Since the beneficial effects of foam occur more rapidly and closer to the wellbore when rapidly foaming surfactants are used, it is expected that oil may be recovered more rapidly, thus the use of rapidly foaming surfactants may provide some economic benefit to offset their higher unit cost. In order to cost-effectively utilize the rapidly foaming surfactants, a multi-stage injection procedure, injecting first a rapidly foaming surfactant with the steam, and then injecting a less rapidly foaming conventional surfactant with the steam may be used. It is also speculated that, when used in combination with other steam foam surfactants, the rapidly foaming surfactants may also be effective at sustaining the steam foam in the formation.